1. Field of the Invention
This invention relates generally to an apparatus and system for making downhole measurements during the drilling of a wellbore. In particular, it relates to an apparatus and system for making downhole measurements at or near the drill bit during directional drilling of a wellbore.
2. Description of the Related Art
In drilling a directional well, it is common to use a bottom hole drilling assembly (BHA) that is attached to a drill collar as part of the drill string. This BHA typically includes (from top down), a drilling motor assembly, a drive shaft system including a bit box, and a drill bit. In addition to the motor, the drilling motor assembly includes a bent housing assembly which has a small bend angle in the lower portion of the BHA. This angle causes the borehole being drilled to curve and gradually establish a new borehole inclination and/or azimuth. During the drilling of a borehole, if the drill string is not rotated, but merely slides downward as the drill bit is being driven by only the motor, the inclination and/or the azimuth of the borehole will gradually change due to the bend angle. Depending upon the "tool face" angle, that is, the angle at which the bit is pointing relative to the high side of the borehole, the borehole can be made to curve at a given azimuth or inclination. If however, the rotation of the drill string is superimposed over that of the output shaft of the motor, the bend point will simply travel around the axis of the borehole so that the bit normally will drill straight ahead at whatever inclination and azimuth have been previously established. The type of drilling motor that is provided with a bent housing is normally referred to as a "steerable system". Thus, various combinations of sliding and rotating drilling procedures can be used to control the borehole trajectory in a manner such that eventually the drilling of a borehole will proceed to a targeted formation. Stabilizers, a bent sub, and a "kick-pad" also can be used to control the angle build rate in sliding drilling, or to ensure the stability of the hole trajectory in the rotating mode.
Referring initially to the configuration of FIG. 1, a drill string 10 generally includes kelly 8, lengths of drill pipe 11 and drill collars 12 as shown suspended in a borehole 13 that is drilled through an earth formation 9. A drill bit 14 at the lower end of the drill string is rotated by the drive shaft 15 connected to the drilling motor assembly 16. This motor is powered by drilling mud circulated down through the bore of the drill string 10 and back up to the surface via the borehole annulus 13a. The motor assembly 16 includes a power section (rotor/stator or turbine) that drives the drill bit and a bent housing 17 that establishes a small bend angle at its bend point which causes the borehole 13 to curve in the plane of the bend angle and gradually establish a new borehole inclination. As noted above, if rotation of the drill string 10 is superimposed over the rotation of the drive shaft 15, the borehole 13 will be drilled straight ahead as the bend point merely orbits about the axis of the borehole. The bent housing can be a fixed angle device, or it can be a surface adjustable assembly. The bent housing also can be a downhole adjustable assembly as disclosed in U.S. Pat. No. 5,117,927 which is incorporated herein by reference. Alternately, the motor assembly 16 can include a straight housing and can be used in association with a bent sub well known in the art and located in the drill string above the motor assembly 16 to provide the bend angle.
Above the motor in this drill string is a conventional measurement while drilling (MWD) tool 18 which has sensors that measure various downhole parameters. Drilling, drill bit and earth formation parameters are the types of parameters measured by the MWD system. Drilling parameters include the direction and inclination (D&I) of the BHA. Drill bit parameters include measurements such as weight on bit (WOB), torque on bit and drive shaft speed. Formation parameters include measurements such as natural gamma ray emission, resistivity of the formations and other parameters that characterize the formation. Measurement signals, representative of these downhole parameters and characteristics, taken by the MWD system are telemetered to the surface by transmitters in real time or recorded in memory for use when the BHA is brought back to the surface.
As shown in FIG. 1, when an MWD tool 18, such as the one disclosed in commonly-assigned U.S. Pat. No. 5,375,098, is used in combination with a drilling motor 16, the MWD tool 18 is located above the motor and a substantial distance from the drill bit. Including the length of a non-magnetic spacer collar and other components that typically are connected between the MWD tool and the motor, the MWD tool may be positioned as much as 20 to 40 feet above the drill bit. These substantial distances between the MWD sensors in the MWD tool and the drill bit mean that the MWD tool's measurements of the downhole conditions, related to drilling and the drill bit at a particular drill bit location, are made a substantial time after the drill bit has passed that location. Therefore, if there is a need to adjust the borehole trajectory based on information from the MWD sensors, the drill bit will have already traveled some additional distance before the need to adjust is apparent. Adjustment of the borehole trajectory under these circumstances can be a difficult and costly task. Although such large distances between the drill bit and the measurement sensors can be tolerated for some drilling applications, there is a growing desire, especially when drilling directional wells, to make the measurements as close to the drill bit as possible.
Two main drilling parameters, the drill bit direction and inclination are typically calculated by extrapolation of the direction and inclination measurements from the MWD tool to the bit position, assuming a rigid BHA and drill pipe system. This extrapolation method results in substantial error in the borehole inclination at the bit especially when drilling smaller diameter holes (less than 6 inches) and when drilling short radius and re-entry wells.
Another area of directional drilling that requires very accurate control over the borehole trajectory is "extended reach" drilling applications. These applications require careful monitoring and control in order to ensure that a borehole enters a target formation at the planned location. In addition to entering a formation at a predetermined location, it is often necessary to maintain the borehole drilling horizontally in the formation. It is also desirable for a borehole to be extended along a path that optimizes the production of oil, rather than water which is found in lower portions of a formation, or gas found in the upper portion of a formation.
In addition to making downhole measurements which enable accurate control over borehole trajectory, such as the inclination of the borehole near the bit, it is also highly desirable to make measurements of certain properties of the earth formations through which the borehole passes. These measurements are particularly desirable where such properties can be used in connection with borehole trajectory control. For example, identifying a specific layer of the formation such as a layer of shale having properties that are known from logs of previously drilled wells, and which is known to lie a certain distance above the target formation, can be used in selecting where to begin curving the borehole to insure that a certain radius of curvature will indeed place the borehole within the targeted formation. A shale formation marker, for example, can generally be detected by its relatively high level of natural radioactivity, while a marker sandstone formation having a high salt water saturation can be detected by its relatively low electrical resistivity. Once the borehole has been curved so that it extends generally horizontally within the target formation, these same measurements can be used to determine whether the borehole is being drilled too high or too low in the formation. This determination can be based on the fact that a high gamma ray measurement can be interpreted to mean that the hole is approaching the top of the formation where a shale lies, and a low resistivity reading can be interpreted to mean that the borehole is near the bottom of the formation where the pore spaces typically are saturated with water. However, as with D&I measurements, sensors that measure formation characteristics are located at large distances from the drill bit.
One approach, by which the problems associated with the distance of the D&I measurements, borehole trajectory measurements and other tool measurements from the drill bit can be alleviated, is to bring the measuring sensors closer to the drill bit by locating sensors in the drill string section below the drilling motor. However, since the lower section of the drill string is typically crowded with a large number of components such as a drilling motor power section, bent housing, bearing assemblies and one or more stabilizers, the inclusion of measuring instruments near the bit requires the addressing of several major problems that would be created by positioning measuring instruments near the drill bit. For example, there is the major problem associated with telemetering signals that are representative of such downhole measurements uphole, through or around the motor assembly, in a practical and reliable way.
A concept for moving the sensors closer to the drill bit was implemented in Orban et. al, U.S. Pat. No. 5,448,227. This patent is directed to a sensor sub or assembly that is located in the drill string at the bottom of the motor assembly, and which includes various transducers and other means for measuring parameters such as inclination of the borehole, the natural gamma ray emission and electrical resistivity of the formations, and variables related to the performance of the drilling motor. Signals representative of such measurements are telemetered uphole, through the wall of the drill string or through the formation, a relatively short distance to a receiver system that supplies corresponding signals to the MWD tool located above the drilling motor. The receiver system can either be connected to the MWD tool or be a part of the MWD tool. The MWD tool then relays the information to the surface where it is detected and decoded substantially in real time. Although the techniques of this patent make substantial progress in moving sensors closer to the drill bit and overcoming some of the major telemetry concerns, the sensors are still approximately 6 to 10 feet from the drill bit. In addition, the sensors are still located in the motor assembly and the integration of these sensors into the motor assembly can be a complicated process.
A technique that attempts to address the problem of telemetering the measured signals uphole around the motor assembly to the MWD tool uses an electromagnetic transmission scheme to transmit measurements from behind the drill bit. In this system, a fixed frequency current signal is induced through the drill collar by a toroidal coil transmitter. As a result, the current flows through the drill string to the receiver with a return path through the formation. The propagation mode is known as a Transverse Magnetic (TM) mode. In this propagation mode, transmission is unreliable in extremely resistive formations, in formations with very resistive layers alternating with conductive layers, and in oil-based mud with poor bit contact with the formation.
Therefore, there still remains a need for a system that can improve the accuracy of bit measurements by placing sensors at the drill bit and reliably transmitting these signals uphole to MWD equipment for transmission to the earth's surface.
As earlier stated there can be a substantial distance between the drilling motor and the drill bit. This distance is caused by several pieces of equipment that are necessary for the drilling operation. One piece of equipment is the shaft used to connect the motor rotor to the drill bit. The motor rotates the shaft which rotates the drill bit during drilling. The drill bit is connected to the shaft via a bit box. The bit box is a metal holding device that fits into the bowl of a rotary table and is used to screw the bit to (make up) or unscrew (break out) the bit from the drill string by rotating the drill string. The bit box is sized according to the size of the drill bit. In addition, the bit box has the internal capacity to contain equipment.
FIG. 2 illustrates a conventional drilling motor system. A bit box 19 at the bottom portion of the drive shaft 15 connects a drill bit 14 to the drive shaft 15. The drive shaft 15 is also connected to the drilling motor power section 16 via the transmission assembly 16a and the bearing section 20. The shaft channel 15a is the means through which fluid flows to the drill bit during the drilling process. The fluid also carries formation cuttings from the drill bit to the surface. In the drilling system of FIG. 2, no instrumentation is located in or near the bit box 19 or drill bit 14. The closest that the instruments would be to the drill bit would be in the lower portion of the motor power section 16 as described in U.S. Pat. No. 5,448,227 or in the MWD tool 18. As previously stated, the sensor location is still approximately 6 to 10 feet from the drill bit. The positioning of measurement instrumentation in the bit box would substantially reduce the distance from the drill bit to the measurement instrumentation. This reduced distance would provide an earlier reading of the drilling conditions at a particular drilling location. The earlier reading will result in an earlier response by the driller to the received measurement information when a response is necessary or desired.
In view of the above, it is a general object of the present invention to provide a more accurate determination of the detected drilling, drill bit and earth formation parameters and characteristics for transmission to uphole equipment during the drilling of a borehole.
Another object of the present invention is to provide improved control of borehole trajectory during the drilling of wells (in particular, short-radius, re-entry and horizontal wells).
A third object of the present invention is to provide a system for making borehole measurements at the actual point of the formation drilling.
A fourth object of the present invention is to provide an instrumented drill bit that can perform drilling, drill bit and formation measurements at the drill bit location during the drilling of a well.